Natural gas is an important source of light hydrocarbon fuel comprising predominantly methane, and is increasingly used in place of conventional fuels due to its wide availability and relative ease of extraction compared to conventional fuels refined from crude oil. However, a lot of natural gas reservoirs contain a substantially high fraction of impurities, such as carbon dioxide (CO2). Some natural gas reservoirs may contain CO2 content of higher than 30%, for instance 50% to 60%, and up to 70%-90%. Other impurities may include compounds such as hydrogen sulfide (H2S), nitrogen (N2) and carbon monoxide (CO). In most reservoirs however, CO2 usually forms the main impurity component of the extracted raw natural gas. Hence, there is a need to process the raw natural gas to remove the CO2 before the natural gas can be efficiently employed for energy generation. Therefore, there have been numerous methods proposed in the art to remove CO2 from a raw hydrocarbon stream such as natural gas.
One known method relates to a gas separation method wherein the raw natural gas is caused to flow through a membrane. As the different gaseous components in the natural gas will permeate the membrane at rates distinct from the permeation rate of methane, the raw natural gas stream becomes separated into a methane-rich stream and an impurity-rich stream. However, one drawback of such a method is that the primary driving force for the separation is the difference in partial pressure of the permeating component in the permeate stream and the retentate stream. As such, the efficiency of separation decreases with time as lesser impurities remain entrained in the natural gas stream. Furthermore, as some methane is expected to permeate through the membrane along with the impurities, there can be significant losses in methane yield of up to 20%. Yet another drawback of the gas separation technique is that impurities such as CO2 are separated in gaseous form. Since acidic gases such as CO2 and H2S cannot be discharged directly to the environment, there is a need to provide storage facilities for the CO2, which usually requires a compression step to convert the gaseous CO2 to a highly pressurized state for optimal storage. This compression step is energy intensive and results in high energy consumption and costs.
Another known method for removing CO2 from hydrocarbons is gas scrubbing wherein the natural gas is contacted with a suitable absorbent medium in an absorption column, such as a packed-bed column. Typically, amine absorbents such as monoethanolamine (MEA), diethanolamine (DEA) methyldiethanolamine (MDEA), diisoproylamine (DIPA) are used because they readily absorb acidic gases such as CO2. However, one of the drawbacks of gas scrubbing is that it requires the procurement of expensive amine absorbents and which require constant regeneration by stripping with high temperature gases (e.g. steam) to regenerate a lean-amine stream that is recycled back to the absorption column for further scrubbing. The regeneration process inevitably results in some amine loss and there is a need to periodically top up the amine absorbent. Furthermore, absorption columns are known to experience problems such as flooding, foaming and entrainment and are costly to install and maintain.
Therefore, there is a need to provide a method and a system for removing CO2 from hydrocarbons that overcomes or at least ameliorates the disadvantages disclosed above. In particular, there is need to provide a method or system for producing a product natural gas stream having no more than 10%, preferably less than 5%, more preferably less than 3% carbon dioxide, from a feed stream containing high concentrations of CO2, which overcomes or ameliorates the disadvantages provided above.